Exall Energy Corporation announces December 31, 2012 third party reserves assessment and provides operational update

Exall Energy Corporation announces December 31, 2012 third party reserves 
assessment and provides operational update 
CALGARY, Feb. 6, 2013 /CNW Telbec/ - Exall Energy Corporation ("Exall" or the 
"Company") (TSX:EE and TSX:EE.DB) is pleased to announce the results of its 
independent third party NI 51-101 compliant reserves assessment and provide an 
operational update concerning its Marten Mountain, Mitsue operating area. 
Exall's public filings can all be found at www.exall.com or www.sedar.com. 
Highlights: 


    --  January 28 to February 3, 2013 weekly Field Production Average
        of 1,409 BOEPD
    --  December 31, 2012 proved plus probable net present value per
        share of $1.69 (Before Tax, discounted at 10%) based on 66.6
        million fully diluted shares
    --  December 31, 2012 company working interest reserves are 2,569.4
        Mboe total proved, a 25% increase from December 31, 2011 (a 38%
        increase when factoring in the Jayar September 30, 2012
        disposition), and 4,629.1 Mboe proved plus probable, a 1%
        increase from December 31, 2011 (an 8% increase when factoring
        in the Jayar September 30, 2012 disposition)
    --  The December 31, 2012 net present value of the proved plus
        probable reserves decreased 33% from December 31, 2011 to
        $112.5 million, discounted at 10 percent, forecast prices,
        before tax. This is reflective of the 35% decrease in the
        proved plus probable Unit Value received at December 31, 2012
        of $36.09 from the December 31, 2011 Unit Value received of
        $55.21, a direct result of the change in the forecast pricing
        utilized by Deloitte in the December 31, 2012 reserve report
        from the December 31, 2011 reserve report.
    --  Reserve life index of 6.5 years total proved and 11.7 years
        proved plus probable based on the 2012 annual average
        production rate and year-end reserves, this represents an
        increase of 33% in the total proved reserve life index and a 6%
        increase in the proved plus probable reserve life index from
        December 31, 2011
    --  2013 Capital Budget of $29.4 million
    --  Exall expects to drill up to 13.0 gross (9.40 net) wells during
        2013, with two wells (1.51 net) having been spud so far in 2013
    --  Exall expects to generate a 2013 Cash Flow of $29.4 million and
        a 2013 average production rate of 1,500 - 1,700 boepd
    Current Production  

Production and Waterfloods

Exall's weekly average daily production from January 28(th) to February 3(rd) 
is approximately 1,409 boepd, an increase of 42% over the Q3 2012 production 
average of 991 boepd and an increase of 27% over the estimated 2012 fourth 
quarter production average of 1,106 boepd. This does not include production 
from the most recently drilled well which will be brought on stream towards 
the end of the first quarter of 2013.

The Company groups the Waterflood Approvals in the Marten Mountain area into 
three project areas; the South WF, Central WF and North WF. The production 
issues faced in these three project areas are being successfully addressed, as 
described below.

Reservoir conformance issues presented challenges in the south waterflood 
during 2012. Optimization efforts aimed at improving well performance and 
oil recovery appear to be having a positive effect. Polymer treatments were 
performed on two injection wells resulting in reduced water cuts in one 
adjacent well, along with an increase in oil production. Current production 
from the South WF area is 428 boepd (310 boepd net), an increase of 26% from 
340 boepd (243 boepd net) through November, 2012.

The Central WF continues to improve as the result of well optimization and the 
installation of an Electric Submersible Pump (ESP) into the newest producing 
well. The new oil well, which was producing 165 boepd, is now producing at 406 
boepd (292 boepd net). The Central WF project is currently producing 783 boepd 
(546 boepd net), an increase of 144% over the Q3 2012 average.

A water source well was drilled, completed and equipped during Q4 2012 and 
injection of water has begun in the North WF Approval area. Optimization 
efforts in the North WF and the addition of two producing wells has increased 
production from 375 boepd (253 boepd net) in August 2012 to an average of 794 
boepd (541 boepd net) over the last week, an increase of 112%.

Exall Price Differentials

The Company's Marten Mountain oil production attracts a price based on the 
average of the daily settlement price of the NYMEX near month Light Sweet 
Crude Oil contract as it trades, excluding weekends / holidays, for the 
calendar month of production, plus the weighted average of the Net Energy 
Index and the NGX index for Light Sweet Crude Oil, plus the one month prior 
Enbridge Sweet WADF. This pricing is adjusted for battery quality, pipeline 
and terminaling fees of $5.00/m3, the then current Rainbow loss allowance and 
a Tunkline Tariff.

As a result, when comparing the Company's oil price received to the posted 
Edmonton Par Price on the Natural Resources Canada website 
(http://www.nrcan.gc.ca/energy/sources/petroleum-crude-prices/crude/1632), 
Exall received an average 2012 price differential of $1.22. Based on the $1.22 
differential Exall forecasts that its January 2013 price received was $86.52 
per barrel, at the delivery point.

2012 Reserve Report

Exall retained AJM / Deloitte Petroleum Consultants ("Deloitte") to conduct an 
independent evaluation of Exall's oil and gas reserves effective December 31, 
2012, which was provided to Exall in an Evaluation Report dated February 05, 
2013 (herein referred to as the "Deloitte Evaluation"). The oil and gas 
reserves and income projections were estimated by Deloitte in accordance with 
the Canadian Oil and Gas Handbook ("COGEH") and National Instrument 51-101 
("NI 51-101").

Summary of Reserve Value - Forecast Pricing

The following tables, extracted from the Deloitte Evaluation, summarize the 
Corporation's total reserves and net present values of future net reserves 
based on forecast pricing and costs as at December 31, 2012. It should not 
be assumed that the estimated future net cash flow shown below is 
representative of the fair market value of the Company's properties. There is 
no assurance that such price and cost assumptions will be attained and 
variances, both positive and negative, could be material.
                                                                


                            Light &   Natural
Company Gross Reserves((1))    medium oil   gas    NGL    Total
as at December 31, 2012          (Mbbl)   (MMcf)  (Mbbl) (Mboe) 


                                                                

Proved developed producing        1,599.9   335.0   14.9 1,670.6

Proved developed non-producing      270.6    44.3    2.0   279.9

Proved undeveloped                  595.0   112.8    5.0   618.8

Total proved                      2,465.4   492.1   21.9 2,569.4

Probable                          1,999.1   286.7   12.8 2,059.7

Total proved plus probable        4,464.5   778.8   34.7 4,629.1

(1) Columns and rows may not add due to rounding
                                                                     
                                             Before Income Tax
                                            $000s, discounted at

Forecast Net Revenue((1))
as at December 31, 2012             0%        5%       10%      15%
                                                                     

Proved developed producing      64,531.8  57,599.4  52,154.9 47,782.1

Proved developed non-producing   7,094.6   5,721.0   4,681.1  3,876.4

Proved undeveloped              20,987.9  17,084.3  14,109.6 11,790.4

Total proved                    92,614.3  80,404.7  70,945.7 63,448.9

Probable                        71,555.2  53,701.8  41,588.0 32,977.3

Total proved plus probable     164,169.5 134,106.5 112,533.7 96,466.2

(1) Columns and rows may not add due to rounding
    Summary of Unit Value Received

The Unit Value before income tax (discounted at 10%) is calculated by dividing 
the Net Present Value of Future Net Revenue before income tax (discounted at 
10%) by the Working Interest After Royalty Reserves. For the December 31, 2012 
Reserves Exall's Unit Value on total proved basis is $41.29, while the total 
proved plus probable Unit Value is $36.09. The represents a total proved Unit 
Value decrease of 26.75% from the December 31, 2011 total proved Unit Value of 
$56.37 and a proved plus probable Unit Value decrease of 34.63% from the 
December 31, 2011 proved plus probable Unit Value of $55.21.

This decrease is reflective of the change in the forecast pricing utilized by 
Deloitte in the December 31, 2012 reserve report from the December 31, 2011 
reserve report.

Summary of Forecast Pricing

Future prices used in the forecast of net revenue are based on those estimated 
by Deloitte as at December 31, 2012. The following table sets forth the 
relevant portions of Deloitte's forecast of commodity prices and costs used in 
the Deloitte Evaluation:
                                              Natural Gas Liquids                                


    WTI     Edmonton   Natural      Edm.       Edm.               Currency    Price     Cost
Year Crude Oil City Gate     Gas      Propane     Butane   Edm. C(5+) Exchange  Inflation Inflation 
 ($US/BBL) ($CDN/BBL)  at AECO   ($CDN/BBL) ($CDN/BBL) ($CDN/BBL)   Rate      Rate      Rate 


                          ($CDN/MCF)                                  ($US/CDN)    (%)       (%)

2013   $90.00     $85.00     $3.20      $46.75     $72.25     $89.25     1.00       0.0       0.0

2014   $89.75     $84.70     $3.75      $46.60     $72.00     $88.95     1.00       2.0       2.0

2015   $91.55     $89.45     $4.05      $49.20     $76.05     $93.90     1.00       2.0       2.0

2016   $93.40     $91.20     $4.35      $50.15     $77.50     $95.75     1.00       2.0       2.0

2017   $92.00     $89.80     $4.65      $49.40     $76.35     $94.30     1.00       2.0       2.0

2018   $93.85     $91.60     $5.10      $50.40     $77.85     $96.20     1.00       2.0       2.0

2019   $95.70     $93.40     $5.40      $51.35     $79.40     $98.05     1.00       2.0       2.0

2020   $97.65     $95.30     $5.75      $52.40     $81.00    $100.05     1.00       2.0       2.0

2021   $99.60     $97.20     $6.10      $53.45     $82.60    $102.05     1.00       2.0       2.0

2022  $101.60     $99.15     $6.45      $54.55     $84.30    $104.10     1.00       2.0       2.0

2023  $103.60    $101.10     $6.95      $55.60     $85.95    $106.15     1.00       2.0       2.0

2024  $105.70    $103.15     $7.10      $56.75     $87.70    $108.30     1.00       2.0       2.0

2025  $107.80    $105.20     $7.25      $57.85     $89.40    $110.45     1.00       2.0       2.0

2026  $109.95    $107.30     $7.35      $59.00     $91.20    $112.65     1.00       2.0       2.0

2027  $112.15    $109.45     $7.50      $60.20     $93.05    $114.90     1.00       2.0       2.0

2028  $114.40    $111.65     $7.65      $61.40     $94.90    $117.25     1.00       2.0       2.0

2029  $116.70    $113.85     $7.80      $62.60     $96.75    $119.55     1.00       2.0       2.0

2030  $119.00    $116.15     $8.00      $63.90     $98.75    $121.95     1.00       2.0       2.0

2031  $121.40    $118.45     $8.15      $65.15    $100.70    $124.35     1.00       2.0       2.0

2032  $123.85    $120.85     $8.30      $66.45    $102.70    $126.90     1.00       2.0       2.0

2033   2.0 %     2.0 %      2.0 %      2.0 %      2.0 %       2.0%       1.00       2.0       2.0
 +   escalated escalated  escalated  escalated  escalated  escalated
    Reserve Reconciliation
                                                                      


                              Light &    Natural
Reserve Reconciliation((1))      medium oil    gas     NGL      Total
(Company Working Interest)         (Mstb)    (MMcf)   (Mstb)   (Mboe) 
                                                                   
Proved                                                                 
December 31, 2011                 1,818.8   1,194.6   30.3   2,048.3 
Extensions & improved recovery    1,500.1     230.7   10.3   1,548.8 
Technical revisions               (475.9)    (49.6)    5.1   (479.1) 
Economic Factors                      0.1    (18.6)  (0.5)     (3.5) 
Acquisitions                          0.0       0.0    0.0       0.0 
Dispositions                       (34.1)   (802.5) (20.5)   (188.3) 
Production                        (343.6)    (62.5)  (2.8)   (356.8) 
December 31, 2012                 2,465.4     492.1   21.9   2,569.4 
                                                                   
Probable                                                               
December 31, 2011                 2,390.6     705.9   17.9   2,526.2 
Extensions & improved recovery      463.4       1.6    0.1     463.8 
Technical revisions               (832.8)      23.0    6.1   (822.9) 
Economic Factors                    (1.1)    (16.9)  (0.4)     (4.3) 
Acquisitions                          0.0       0.0    0.0       0.0 
Dispositions                       (21.0)   (426.9) (10.9)   (103.1) 
Production                            0.0       0.0    0.0       0.0 
December 31, 2012                 1,999.1     286.7   12.8   2,059.7 
                                                                   
Proved plus Probable                                                   
December 31, 2011                 4,209.5   1,900.6   48.2   4,574.5 
Extensions & improved recovery    1,963.5     232.3   10.4   2,012.6 
Technical revisions             (1,308.8)    (26.6)   11.3 (1,302.0) 
Economic Factors                    (1.0)    (35.6)  (0.9)     (7.8) 
Acquisitions                          0.0       0.0    0.0       0.0 
Dispositions                       (55.1) (1,229.4) (31.5)   (291.4) 
Production                        (343.6)    (62.5)  (2.8)   (356.8) 
December 31, 2012                 4,464.5     778.8   34.7   4,629.1 
(1) Columns and rows may not add due to rounding 
2013 Capital Program 
The Company's Board of Directors has approved an exploration and development 
expenditures program of $29.4 million for 2013 (the "2013 Capital Budget"). 
The 2013 Capital Budget is expected to be self-financed by funds from 
operations and will be adjusted from time to time to reflect production and 
cash flow achievements. 
The initial 2013 Capital Budget will encompass the continued, focused 
development of Exall's 66 - 73.5%-owned, Gilwood light sweet crude oil play. 
At Marten Mountain in Mitsue, Alberta, the Company plans to drill 13 gross 
(9.40 net) wells with 3.0 gross (2.16 net) exploration wells and 10 gross 
(7.24 net) development wells being drilled on the North 3D Seismic channel. 
The drilling and completion expenditure component of Exall's 2013 Capital 
Budget is projected to approximate $25.7 million, with remaining budgeted 
funds of approximately $3.75 million allocated towards investments in 
well-site equipment, field facilities, and gathering lines. 
"I am very excited about the coming year. All the work we have focused on over 
the last half of 2012 has positioned us to make significant gains in 2013 
through 2015," said Roger Dueck, President and Chief Executive Officer. 
"Exall's 2013 capital budget focuses investment on those projects which are 
expected to generate the highest returns and lead to near-term production and 
cash flow gains. Accelerating production and cash flows will further improve 
the company's financial strength to support our significant growth plans," 
said Dueck. 
"Our production target for 2013 is approximately 45 percent above estimated 
2012 volumes and we expect further increases that will double current rates in 
2014″ said Dueck. "At the same time that we are driving towards higher 
production, efficiency improvements are expected to reduce operating costs to 
$10 to $12 per barrel in 2013 from our 2012 rates of $13.50 per barrel." 
Based on the budgeted capital expenditures anticipated within the 2013 Capital 
Budget, average daily production for fiscal 2013 is projected to range between 
1,500 - 1,700 boepd, weighted approximately 97% light sweet crude oil and NGLs 
and 3% natural gas. This forecasted production range represents a 39 - 57% 
increase over the Company's 2012 average daily production estimate. 
Assuming the median of the forecasted average daily production range and 
utilizing 2013 pricing assumptions of US$85.00 per bbl for Edmonton Par oil, 
and AECO gas price of C$3.39 per gigajoule, the Company's funds from 
operations for 2013 is estimated at $0.44 per basic share or approximately 
$29.4 million in aggregate, which represents a significant increase of 78%, 
over projected 2012 funds from operations. Field operating netbacks for 2013 
are forecasted at approximately $57 - $62/boe, as compared to the estimated 
$52.50/boe netback for 2012, reflecting the Company's successful ongoing 
development of its light sweet crude oil play at Mitsue, Alberta. 
Based on the 2013 Capital Budget and projected funds from operations, Exall's 
year-end 2013 net debt is estimated at $59 million ($36.0 Million in Bank Debt 
plus $23.0 Million in Convertible Debentures due March 31, 2017) or 
approximately 2.0 times forecasted 2013 funds from operations. 
About Exall 
Exall is a junior oil and gas company active in its business of oil and gas 
exploration, development and production from its properties in Alberta. Exall 
Energy is currently developing the new Mitsue area "Marten Mountain" discovery 
in north-central Alberta. 
Exall Energy currently has 66,634,854 common shares outstanding. The Company's 
common shares are listed on the Toronto Stock Exchange under the trading 
symbol EE. The Company's convertible debentures are listed on the Toronto 
Stock Exchange under the trading symbol EE.DB. 
Reader Advisory 
This news release contains forward-looking statements, which are subject to 
certain risks, uncertainties and assumptions, including those relating to 
results of operations and financial condition, capital spending, financing 
sources, commodity prices and costs of production. By their nature, 
forward-looking statements are subject to numerous risks and uncertainties 
that could significantly affect anticipated results in the future and, 
accordingly, actual results may differ materially from those predicted. A 
number of factors could cause actual results to differ materially from the 
results discussed in such statements, and there is no assurance that actual 
results will be consistent with them. Such factors include 
fluctuatingcommodity prices,capital spending and costs ofproduction, and 
other factors described in the Company's most recent Annual Information Form 
under the heading "Risk Factors" which has been filed electronically by means 
of the System for Electronic Document Analysis and Retrieval ("SEDAR") located 
at www.sedar.com. Such forward-looking statements are made as at the date of 
this news release, and theCompany assumes no obligation to update or revise 
them, either publicly or otherwise, to reflect new events, information or 
circumstances, except as may be required under applicable securities law. 
For the purposes of calculating unit costs, natural gas has been converted to 
a barrel of oil equivalent (boe) using 6,000 cubic feet equal to one barrel 
(6:1), unless otherwise stated. The boe conversion ratio of 6 mcf: 1 bbl is 
based on an energy equivalency conversion method and does not represent a 
value equivalency; therefore boe may be misleading if used in isolation. This 
conversion conforms to the Canadian Securities Regulators' National Instrument 
51-101 - Standards of Disclosure for Oil and Gas Activities. 
Exall Energy Corporation Frank S. Rebeyka Vice Chairman Tel: 403-815-6637 
Roger N. Dueck President & CEO Tel: 403-237-7820 x 223 info@exall.com 
Please visit Exall Energy's website at:www.exall.com 
Renmark Financial Communications Inc. Maurice 
Dagenais:mdagenais@renmarkfinancial.com Nadia 
Marks:nmarks@renmarkfinancial.com Tel.: (416) 644-2020 or (514) 939-3989 
www.renmarkfinancial.com 
PDF available at:  
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PDF available at:  
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SOURCE: EXALL ENERGY CORPORATION 
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CO: EXALL ENERGY CORPORATION
ST: Quebec
NI: OIL  
-0- Feb/06/2013 12:30 GMT
 
 
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